Gas hydrates resources in subterranean formations have been estimated to represent more than twice the energy of all known coal, oil and gas. In spite of this large quantity of in-place hydrate resources, current extraction efforts have not yet led to widespread exploitation of gas hydrates from subterranean formations.
Gas hydrates or clathrates, as they are commonly known, are a mixture of water and gas, where the water forms a rigid, cage-like structure that is filled with a gas molecule. Most commonly, the gas is biogenic methane, but can be thermogenic methane, CO2, and occasionally other hydrocarbon gasses such as ethane.
Gas hydrates are naturally occurring, but are only stable within a limited range of temperature and pressure conditions, known as the gas hydrate stability zone (GHSZ). Hydrates are found in clastic marine sediments, siltstones, unconsolidated sands, and poorly cemented sandstones and conglomerates. The temperature and pressure restrictions limit hydrate formation to some ocean sediments and on-shore sediments of the permafrost regions of the Arctic.
There are three known forms of gas hydrates: structure I, structure II and structure H. Structure I and structure II hydrates are by far the most common, while structure H hydrates are extremely rare and will not be addressed further here.
A structure I or structure II gas hydrate in a sandstone with 38% porosity and 85% hydrate saturation would have a gas yield at standard temperature and pressure (STP) of 164 m3/m3 of gas hydrate. This would also result in 0.8 m3 of water at STP. It is unclear how much methane is trapped in all gas hydrates worldwide, with some estimates ranging from 3,114 to 7,634,000 trillion m3. The main reason for this extremely large range of estimates is that there are several unknown factors including: the lateral extent of gas hydrate deposits, the reservoir porosity, reservoir thickness, and the level of saturation of methane in a given deposit. Part of the reason for these uncertainties is because core is extremely difficult to recover and accurately measure in a laboratory setting as it must be kept at freezing temperatures to prevent the hydrate from dissociating.
The primary interest in gas hydrates is due to the aforementioned large quantity of methane that is contained by them. A significant research initiative has been implemented to find a way to produce this methane in an economically favorable manner. As previously mentioned, it has been estimated that the total energy corresponding to the natural gas trapped in hydrate reservoirs is more than twice the energy of all known coal, oil and gas. It is important to note that gas hydrates are not a new phenomenon and have been studied since the 1970's, but were seen primarily as a drilling hazard. Blowouts, fires, and collapsed casing have occurred when drilling through hydrate zones. Gas hydrates have also been known to cause blockages in flow lines and pipelines in Arctic and deepwater marine regions. In submarine regions, slides and slumps on continental margin slopes are a significant geologic hazard. Methane hydrates are also considered a potential factor in climate change due to methane's status as a powerful greenhouse gas and the abundant amount of carbon that is associated with these enormous amounts of gas hydrate.
To produce methane from gas hydrates, the dynamics of how and where they form must be understood. It has been previously shown that gas hydrates are primarily pore-filling rather than grain coating, and therefore greatly reduce permeability. This fact is important because the relative permeability of formations is critically dependent on how hydrate forms in the pore space of rock and sediment, with permeability being one of the most important factors in being able to produce methane from gas hydrate deposits. For example, in a 1.1 Darcy core, permeability was reduced to a few mD at high levels of hydrate saturation (˜62%).
One interesting aspect of hydrate formation is that they exclude salts from the ice lattice when they form. The fate of these ions, however, is a mystery. If they were to concentrate in any remaining water, one would expect a reduced resistivity of formation water (Rw) in hydrate bearing intervals as compared to water saturated sands above and below the hydrate interval; however, this is not the case. In one well that was studied, water resistivity (Rw) was back-calculated from the NMR hydrate saturation and the hydrate bearing intervals actually had a slightly elevated Rw compared to the surrounding water sand intervals (0.20-0.50 versus 0.20-0.30, respectively). This difference could be a product of ion migration or it could mean that the ions are trapped in or around the hydrate lattice and are effectively bound. This would render the ions unable to conduct electrical current and thus not allow the ions to be recognized by electrical resistivity logging.
The failure to exploit large reserves of gas hydrates is due in part to the ineffectiveness of current methods for detecting and evaluating the petrophysical properties of a formation and the presence of hydrates in subterranean formations as a function of depth. One example of a conventional method for evaluating the petrophysical properties of a formation is taking a core sample. Of the conventional methods, core sampling can provide the most detailed information about a formation's petrophysical properties. Unfortunately, taking core samples is a time-consuming, laborious, and costly process, fraught with numerous technical complications and pitfalls. Additionally, core samples often require intensive laboratory analysis and hence, high costs and delays. Often, taking a full core sample of a wellbore is simply not feasible, particularly for deep and highly deviated wells.
Measurement of gas content in drilling mud is a common means of determining presence of gas in a formation, and in distinguishing permafrost ice from hydrates. This is an important measurement since the gas hydrate stability zone can overlap with depths where permafrost exists.
Sampling while drilling is another common technique to ascertain petrophysical properties of a formation. Again, this conventional method suffers from significant limitations, particularly with respect to the amount of samples that may be taken while drilling and the difficulty in keeping the samples in a frozen state. Furthermore, analysis of these samples is time-consuming and laborious as well.
Another common form of evaluating petrophysical properties of formations is logging. Logging tools provide a variety of noninvasive evaluation techniques for evaluating formations and detecting hydrate presence. Unfortunately, conventional logging tools only provide limited information about a formation's petrophysical properties. Individual logging techniques often fail to accurately detect and accurately evaluate the nature and composition of subterranean formations and the hydrocarbon contained therein. Individual logging techniques are often susceptible to misinterpretation and are susceptible to false positives.
Moreover, often, only a limited number of logging tools are used in some wellbores. Therefore, in these situations petrophysical properties of a formation must be estimated with only a limited set of logging devices, which can be quite challenging.
Therefore, for all of these reasons, there is a need in the art for improved systems and methods that address one or more disadvantages of the prior art for assessing the petrophysical properties of formations, including performing a comprehensive analysis of hydrate presence in a formation.